1. Field of the Process
The present development relates to a method and an apparatus for separating a desired gas component from a gas mixture containing a plurality of gas components. More particularly, the present development relates to a multi-stage adsorption system to separate a methane-bearing feed gas, containing a plurality of components, including, for example, methane, carbon dioxide, nitrogen, oxygen, and water vapor. Other constituents may be present in small quantities in the methane-bearing feed gas, such as, for example, ethane, ethylene, hydrogen, hydrogen sulfide, and propane, with no significant impact on the operation of the present process. The present process produces a methane-rich product gas that meets certain purity requirements, e.g., for liquefaction or for distribution via pipeline, and a byproduct gas containing most of the carbon dioxide, nitrogen, oxygen, and water.
The present multi-stage adsorption system offers significant advantages compared with alternatives, e.g., other sequences of adsorption-based, membrane-based, or cryogenic separators, because of the beneficial effects, in a first embodiment, of using a portion of the waste product that is generated in the third stage, from which the methane-rich product gas also flows, to regenerate adsorbent in the second stage, and to use a portion of the waste product that is generated in the second and third stages to regenerate adsorbent in the first stage. In that first embodiment, the second stage operates by temperature swing adsorption. In a second embodiment, the second stage operates by pressure swing adsorption, and is otherwise practically identical to the first embodiment. In a third embodiment, the functions of the first two stages of the second embodiment are combined. The corresponding advantages for the third embodiment are the result of using a portion of the waste product that is generated in its second stage to regenerate adsorbent in the first stage.
The present multi-stage adsorption system is especially well suited to applications where the feed gas contains at least about 40% methane and at least about 5% carbon dioxide, and amounts to at least about 10 standard cubic feet per minute.
2. Discussion of the Background
Typical applications include, inter alia, production of pipeline-grade or liquefied natural gas (LNG) from methane-bearing feed gas for the merchant gas market. The demand for fuels produced from relatively small sources is increasing. There now is a market for small-scale pipeline-grade or LNG production apparatus, e.g., less than 20,000 standard cubic feet per minute (scfm) using 379.4 scf per pound mole (i.e., about 34,000 normal cubic meters per hour (Nm3/h) using 0.022412 Nm3 per gram mole). This demand has been augmented by the growing enthusiasm for LNG as a fuel for commercial vehicles.
Methane-bearing feed gas is typically produced from a wide variety of sources. Those related to human activities include (along with the percentage of total methane emissions): Landfills (24.1%), Natural Gas Systems (23.1%), Enteric Fermentation (21.1%), Coal Mining (9.9%), Manure Management (7.2%), and Wastewater Treatment (6.8%), which account for 92.1% of the Total, which amounted to 556.7 (Tg CO2 Eq.) 10,580,370 million SCF in 2004. Gob wells at coal mines account for most of the approximate 9.9% listed above [see: “Technical and Economic Assessment of Potential to Upgrade Gob Gas to Pipeline Quality,” US EPA, Report No. 430-R-97-012 (1997), “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2004,” EPA 430-R-06-002, (2006); U.S. EPA and http://www.epa.gov/methane/sources.html (Sep. 3, 2007)].
In order to purify methane-bearing feed gas to meet pipeline standards requires removal of moisture, and in some cases, i.e., depending on the original composition, carbon dioxide, oxygen, and nitrogen. In contrast to pipeline-grade natural gas, LNG offers advantages for storage, as well as shipment, and it provides an environmentally favorable fuel for trucks and buses, though it requires expensive liquefaction equipment. Information regarding LNG including production, imports, exports, and uses may be found at the DOE website (http://www.eia.doe.gov/, (Sep. 3, 2007)).
LNG standards, however, are different from pipeline standards, and the separation requirements are significantly different. Example pipeline-grade and LNG standards are shown in Table 1. A typical commercial LNG separation train has a capacity of 3 million tons per year, about 700,000 lb/hr, or 270,000 scfm (or 440,000 Nm3/h) (Klinkenbijl et al., “Gas Pre-Treatment and their Impact on Liquefaction Processes” paper presented at the Gas Processors Association Meeting, Nashville Tenn., (1999)). Hence, each typical train has a capacity of about 13× that of the largest capacity envisioned by the present process. Those plants use well-known process technology, viz., cryogenic distillation, which is described later. For several reasons, it is difficult to adapt that type of technology to produce LNG economically on a small scale, such as is pertinent here.
TABLE 1Example Requirements for Natural GasComponentPipeline SpecificationLNG SpecificationCO2<1 to 3 mol %<50 ppmvH2O*<0.5 ppmvH2S<0.25 grain/100 scf<3.5 ppmvInerts: N2 + O2 + CO2<4 mol %<5.0 mol %O2<0.1 to 0.3 mol %<1.0 mol %Suspended SolidsNilNil* 4 to 7 lbs./1,000,000 scf = 0.0084 to 0.0147 mol % or 84 to 147 ppmv.
Several means are available for purification and liquefaction of methane-rich gas. Several such processes treat the methane-rich gas by first liquefying it. That means the mixture must be dry and relatively free of carbon dioxide, as listed in the first two rows of the LNG column in Table 1. Some of these means are: (1) Nitrogen Refrigeration Cycle (also called closed Brayton/Claude cycle), (2) Turboexpander at Gas Pressure prop, (3) Precooled Joule-Thomson (JT) Cycle, (4) Cascade Cycle, (5) Mixed-Refrigerant Cycle, (6) Open Cycle with Turboexpander/Claude Cycle, (7) Stirling Cycle (or Phillips Refrigerator), (8) Thermoacoustic Driver Orifice Pulse Tube Refrigerator, and (9) Liquid Nitrogen Open-Cycle Evaporation. Although these methods are useful for liquefaction, none is capable of purifying the methane-bearing feed gas on a continuous basis, however, so they will not be described in any detail. Most of these will fail to operate satisfactorily unless the purity constraints listed in Table 1 are met.
Known techniques for purification of methane-bearing feed gas (containing carbon dioxide, nitrogen, oxygen, and water vapor) comprise at least two sequential units: at least one to remove the bulk of carbon dioxide and water vapor from the other constituents, followed by at least one additional unit to split methane from nitrogen and oxygen. Alternatively, it is possible first to remove nitrogen and oxygen from the other constituents, followed by removing carbon dioxide and water vapor from methane. Frequently, one unit would perform each required separation sequentially, e.g., to separate water from the methane-bearing feed gas producing a first methane-rich intermediate stream, from which carbon dioxide could be removed, producing a second methane-rich intermediate stream, then oxygen from the remaining gas, producing a third methane-rich intermediate stream, and so on, to remove oxygen and nitrogen.
Generally, the known separation techniques fall into only a few general categories: cryogenic distillation including partial condensation via refrigeration (i.e., to collect carbon dioxide and/or water as a liquid or solid), absorption, i.e., of carbon dioxide and/or water using selective solvents, membranes that are selectively permeable to specific components, adsorption processes, and hybrid systems. Prior art related to these five categories is summarized below.
Cryogenic distillation (CD) is a potential method for purifying a methane-bearing feed gas, containing carbon dioxide, nitrogen, and oxygen. It turns out to be less than ideal for a number of reasons explained below. The normal boiling points of these components are: nitrogen (−196° C.), oxygen (−183° C.), methane (−162° C.), carbon dioxide (sublimes at −78° C.), and water vapor (100° C.). The spread of boiling points implies that, if much oxygen is present, a hazardous situation may arise since oxygen and methane may tend to be concentrated together, which would be a hazardous mixture. If there were little oxygen present, nitrogen could be removed safely (as the most volatile component). In addition, carbon dioxide and water vapor pose potential processing problems because they can solidify at the temperature at which methane liquefies, if their partial pressures are too high. Because CD involves contacting the liquid and vapor phases of the mixture to be separated, formation of the solid phases of carbon dioxide and/or water can physically disrupt the separation, i.e., block the flow of liquid and vapor in a distillation column. In addition, solidification may cause a problem in the cold-box heat exchanger, which partially cools the feed mixture to cryogenic conditions, or in the Joule-Thomson valve, which also contributes to cooling. Thus, the feed to a CD column is normally adjusted approximately to meet the carbon dioxide and water vapor standards for LNG (carbon dioxide=50 ppm (vol), water vapor=0.5 ppm (vol), as shown in Table 1). In addition, oxygen must be reduced to a level that is safe for processing in a CD column, which is considerably lower than the LNG requirement listed in Table 1, on account of its tendency to be enriched within the CD apparatus. With those constituents suitably removed, the remaining separation objective is that of methane from nitrogen.
The operation of cryogenic distillation involves partially or fully liquefying the feed gas, under pressure, at low temperatures (as mentioned earlier). Afterwards, the partially or fully condensed feed is fractionated in one or two columns. If the latter, they operate in parallel at different pressures, in order to separate the feed into a nitrogen-rich stream overhead and a methane-rich stream from the bottom. Cooling the incoming feed stream with the overhead nitrogen stream, causing the nitrogen to vaporize prior to being exhausted, can reduce refrigeration cost. To deliver an LNG product, the bottom methane-rich distillation product is delivered to a storage vessel for sales.
Numerous refrigerated distillation processes for separating gas mixtures are taught in the prior art. For example, Holmes et al. (U.S. Pat. No. 4,462,814) describe a process and apparatus for distillation in which an alkane, such as propane or butane, is added to the feed to allow operation with decreased pressures and elevated temperatures, but without solid CO2 formation, i.e., well within the liquid-vapor phase envelope. It, however, is complex, which leads to high capital cost and is impractical to apply to smaller feed streams. Similarly, Potts et al., (U.S. Pat. No. 5,120,338) describe a method for separating a multi-component feed stream using distillation and a controlled freeze zone, different from the Holmes process in that solid carbon dioxide is allowed to form in a controlled manner. This solid is melted and incorporated into the liquid portion of a liquid phase product. A third gas phase is enriched in the most volatile component, methane, allowing its separation. By carefully controlling the conditions of solid formation, and gas-liquid distillation, the components may be separated into three streams. Similarly, Barclay, et al. (U.S. Pat. No. 6,082,133) describe a method for separating carbon dioxide from a mixture (such as biogas). Their idea is based on freezing the carbon dioxide on a refrigerated surface, then causing it to sublime into another gas stream. Their method involves the use of heat integration, such that the sublimed carbon dioxide is used to cool the feed gas, and even the heat of sublimation is partly captured. The primary limitations of these processes are their complexity and the associated capital costs. These are not particularly economical means for removing carbon dioxide. Many cryogenic distillation processes for treating natural gas are focused on nitrogen rejection, such as Oakey and Davis (U.S. Pat. No. 7,059,152).
Absorption also can be effective for splitting carbon dioxide and/or water vapor from methane-bearing feed gas. The range of available absorbents for carbon dioxide includes amines, caustic, and others. Those are generally prepared in aqueous solutions that react with carbon dioxide. Conversely, ethylene glycol is commonly used to physically absorb moisture from gas streams. Removal of methane from the remaining oxygen and nitrogen can be accomplished by lean oil absorption, which involves the absorption of methane in chilled hydrocarbon oil. Since methane is the major component in the mixture, this process is energy-intensive and expensive to operate. In addition, the equipment for this process tends to be expensive, on account of the refrigeration unit and ancillary heat exchangers.
Several independent absorbers and solvent regenerators or strippers are required for purifying the specified methane-bearing feed gas, because the absorbents are specialized. One absorber is needed to capture carbon dioxide, and subsequently another absorber is needed to dry the gas. Finally, a lean-oil absorber is needed to capture the methane, allowing oxygen and nitrogen to pass through. This sequence is necessary since the carbon dioxide absorbent solution does not remove water or methane to an appreciable extent, but rather may introduces additional water into the treated gas, which must subsequently be removed by the dryer. Likewise, the dryer does not remove methane to an appreciable extent. In addition, the carbon dioxide absorber, dryer, and lean-oil absorber units require solvent regenerators, i.e., in which the absorbent solutions are heated and contacted with a compatible gas in order to desorb or strip the absorbed component. Hence, to accomplish the necessary separations via absorption and solvent regeneration requires a total of at least six separation units. In addition to the disadvantage of complexity, the absorbents tend to decompose and to lose effectiveness, produce foam, or become viscous as time proceeds, due to adverse chemical reactions and due to absorption of dilute contaminants. Absorbents, which cannot be fully regenerated, continue to accumulate contaminants, eventually releasing some of the contaminants into the methane-rich product. Consequently, absorbents have the disadvantage of routinely requiring replenishment.
Adler et al. (U.S. Pat. No. 4,270,937) disclose a comprehensive gas separation process for a feed gas containing methane and carbon dioxide together with impurities or contaminants. The Adler process includes an initial liquid carbon dioxide absorption process, which also removes certain contaminants from the feed gas, along with a liquid carbon-dioxide-enriched bottom product of the process. Siwajek et al. (U.S. Pat. No. 5,842,357) describe a process based on absorption which they claim is able to produce methane of sufficient quality for liquefaction, though it does not remove much nitrogen. In order to recover sufficiently pure methane, e.g., to meet LNG standards, on account of the number of absorption and regeneration units, the energy intensity, and the absorbent replenishment cost, the capital and operating expenses are very high. Morrow (U.S. Pat. No. 6,607,585) presents another absorption-based process that removes heavy hydrocarbons, VOCs, carbon dioxide, and hydrogen sulfide.
Membrane separation processes are well known for removing carbon dioxide water vapor, and nitrogen from methane, by using membrane materials that exhibit selective permeation of those relative to methane. Such processes use membrane modules combined as stages to perform the separation, and they exhibit a tradeoff between the recovery and purity of the methane-rich product that is recovered, such that it is impossible with current membrane materials to attain both high purity and high recovery on a single-pass basis. Consequently, to attain high recovery at reasonable purity requires substantial recycle, and power input. For example, Baker et al., (U.S. Pat. No. 6,630,011 B1) describe a variety of processes, which employ two types of membranes. One process uses 3-membrane modules, and another uses 4-membrane module design, which separate nitrogen, methane, and carbon dioxide, plus several hydrocarbon species. The pressures range up to 1,000 psia, and the product quality attained is sufficient for pipelines, but not for LNG. Baker et al. (U.S. Pat. No. 6,579,341) shows a membrane-based process for treating LFG and other methane-rich gases prior to combustion. Membrane processes are expensive for applications such as this, having high purity constraints, on account of high equipment and power costs (largely due to recycle which is necessary to meet purity requirements), which are not feasible except for very low feed flow rates
Cyclic adsorption processes for separating methane-bearing feed gas containing carbon dioxide, nitrogen, oxygen, and water vapor, include pressure swing adsorption (PSA) and temperature swing adsorption (TSA). For example, Dolan and Butwell (U.S. Pat. No. 6,444,012) show a PSA process for separation of nitrogen from natural gas that utilizes two separate PSA stages. The first contains a hydrocarbon-selective adsorbent (e.g., silica) and the second contains a nitrogen-selective adsorbent (e.g., ETS-4). The product stream from the first PSA stage contains a natural gas stream having reduced hydrocarbon content, and the product stream from the second PSA unit is a natural gas stream having a reduced nitrogen concentration. The product from the second PSA unit is used to desorb the hydrocarbons from the first PSA unit so as to recover the hydrocarbons in the product stream. That patent teaches that it was necessary, periodically, to heat the second PSA adsorbent in order to improve the capacity of the nitrogen-selective adsorbent to adsorb nitrogen. Thus, it is partially a TSA process, as well. Butwell, et al., (U.S. Pat. Nos. 6,315,817 and 6,497,750) show a PSA process for separation of nitrogen from natural gas that utilizes two separate PSA stages. The first stage contains a rate-based, nitrogen-selective adsorbent (e.g., CTS-1 or ETS-4) and the second stage contains an equilibrium-based hydrocarbon-selective adsorbent (e.g., 13× zeolite, carbon, or silica gel). The main product stream from the first PSA stage contains a methane-rich stream, i.e., having a reduced nitrogen concentration. The byproduct of the first stage, which is enriched in nitrogen relative to the feed, is treated by the second stage. The main product stream from the second PSA unit has reduced methane content relative to the byproduct from the first stage. The byproduct of the second stage is enriched in methane compared with the byproduct from the first stage, and it is recycled to the first stage. Those patents also teach that it was necessary, periodically, to heat the first PSA adsorbent in order to improve the capacity of the nitrogen-selective adsorbent to adsorb nitrogen. Thus, it is partially a TSA process, as well. Davis, et al. (U.S. Pat. No. 5,174,796) describe a process for purification of natural gas in which the nitrogen content of natural gas is reduced to pipeline quality using a PSA process in which a particular combination of steps in the cycle produces a product natural gas having a reduced nitrogen content, a nitrogen-rich stream, and a high heat content fuel gas stream. Reinhold et al. (U.S. Pat. No. 5,536,300), and Reinhold et al. (U.S. Pat. No. 5,792,239) suggest other means by which the nitrogen and carbon dioxide content of natural gas can be reduced to meet pipeline standards. Sircar et al. (U.S. Pat. No. 4,770,676) describe a PSA process for treatment of LFG, containing methane and 40 to 60% carbon dioxide, to obtain high Btu gas for combustion and, optionally, purified carbon dioxide for industrial applications. Hahn (U.S. Pat. No. 6,631,626 B1) shows an adsorption-based process, in which a nitrogen-selective adsorbent is employed, and a refrigeration cascade used for liquefying the methane-rich product. This patent also includes an allowance for pretreatment to remove undesirable components via compression and absorption with amine solution, refrigeration, or adsorption with disposable adsorbent or regenerable adsorbent.
Dolan and Mitariten (U.S. Patent Application No. US 20060191410 A1) suggests a two-stage process by which C3+ hydrocarbons, nitrogen, and/or carbon dioxide contained in natural gas can be reduced. That application teaches that a methane-containing vent stream can be extracted from the second stage to be used to purge the heavy hydrocarbon-rich gas in the first stage. Mitariten (U.S. Patent Application No. US 2007/0068386 A1) suggests a means by which water vapor, volatile organic compounds (VOCs), siloxanes, and carbon dioxide contained in landfill gas can be reduced. That application teaches that a vent stream that is substantially free of siloxanes can be extracted to be used as a fuel in a gas engine. Carbon dioxide and water vapor can be removed from gas mixtures by an adsorption system sometimes called a pre-purifier. This approach is most commonly applied to air, prior to cryogenic distillation. The feed air is compressed then passed first through a refrigerated dryer (to reduce the dew point temperature to about 40° F. (4° C.), and then through an adsorber where it is cleaned of high boiling impurities such as water vapor and carbon dioxide. In many cases, multiple adsorbent layers are used, including forms of zeolite and/or activated alumina. Such adsorbers can function either as PSA or TSA processes.
Several hybrid techniques that employ cooling along with a second type of separation device. For example, O'Brien et al. (U.S. Pat. No. 4,681,612) describe a cryogenic separation system that produces a fuel-grade methane product and the option of a carbon dioxide product. This approach relies on cryogenic distillation, in which the overhead product is enriched in methane. A selective membrane further purifies the methane from that product. Similarly, Lokhandwala (U.S. Pat. No. 5,647,227) teaches a process and apparatus by which a mixture of methane, nitrogen, and at least one other component (carbon dioxide) are separated. This process employs a cryogenic separation augmented by a membrane. Also using low temperature, Sweeney et al. (U.S. Pat. No. 5,570,582), Soffer et al. (U.S. Pat. No. 5,649,996), and Ojo et al. (U.S. Pat. No. 5,531,808) teach processes by which the operation of adsorption systems is augmented by operation at sub-ambient or cryogenic temperatures. These hybrid systems are complex and expensive, which limit their use. Forte (U.S. Pat. No. 5,321,952) showed a process for purification of natural gas in which the nitrogen content was reduced by a combination of absorption, purification, flashing, and reflux steps. Doshi and Dolan (U.S. Pat. No. 5,411,721) describe a process for the rejection of carbon dioxide from natural gas comprising a gas permeable membrane and a multiple bed pressure swing adsorption system to produce a methane-rich product having a desired concentration of carbon dioxide. The carbon dioxide-rich permeate stream from the membrane system is fed to the PSA unit and a stream essentially free of carbon dioxide gas from the PSA unit is compressed and blended with the retentate to form the mixed gas product. Another combination of a semi-permeable membrane and adsorber was suggested by Prasad, et al. (U.S. Pat. No. 5,116,396).
The usage of chemical additives along with vapor-liquid equilibrium represents another type of hybrid process. Abdelmalek et al. (U.S. Pat. No. 5,642,630), disclose a LFG separation process that claims production of high quality LNG, liquefied carbon dioxide, and compressed natural gas. The patent describes a four-stage compressor to generate pressures up to 1800 psia, as well as three flash drums, the use of chemical additives, and multiple recirculation loops to obtain the desired products. This system is complex and the related capital costs limit its usefulness. A related patent, using methanol as a chemical additive to separate carbon dioxide and methane from landfill gas was reported (Apffel, U.S. Pat. No. 4,675,035). Addition of methanol to the gas mixture during distillation decreases the temperature and pressure range at which solid carbon dioxide will form, allowing the distillation of methane to produce a higher purity product. Methanol can be separated from the carbon dioxide and recycled once the distillation process is complete. “Cold Methanol” separations, as they are called, are effective, but they do not scale well to smaller LFG sources because of the system complexity, capital costs, and operating costs associated with the combined absorption and distillation processing equipment.
The entire contents of each of the above-mentioned patents and references are hereby incorporated by reference, the same as if set forth in their entireties herein.
In view of the prior art, it is evident that there is a commercial need for a cost effective process for treating feed gas comprised of, at a minimum, methane, carbon dioxide, nitrogen, oxygen, and water vapor, into a methane-rich product that is suitable for liquefaction or distribution via pipeline. There also is a commercial need to provide a separation system that uses the waste product from one part of the system to effect regeneration of adsorbent in another part of the system, and thereby to improve the efficiency of the separation. There is a further commercial need to provide a separation system that achieves high product quality and excellent product recovery, but with the least possible complexity and lowest possible operating cost. It is to these needs that the present development is addressed.